1. Field
This disclosure relates to servicing a wellbore. More specifically, it relates to servicing a wellbore with cement compositions comprising gelation inhibiting retarders and methods of making and using same.
2. Background
Natural resources such as gas, oil, and water residing in a subterranean formation or zone are usually recovered by drilling a wellbore down to the subterranean formation while circulating a drilling fluid in the wellbore. After terminating the circulation of the drilling fluid, a string of pipe (e.g., casing) is run in the wellbore. The drilling fluid is then usually circulated downward through the interior of the pipe and upward through the annulus, which is located between the exterior of the pipe and the walls of the wellbore. Next, primary cementing is typically performed whereby a cement slurry is placed in the annulus and permitted to set into a hard mass (i.e., sheath) to thereby attach the string of pipe to the walls of the wellbore and seal the annulus. Subsequent secondary cementing operations may also be performed.
Generally, cements suitable for wellbore servicing meet standards defined by the American Petroleum Institute (API). These types of cements, designated API cements, are formulated to exhibit a process-desired rheology such as consistent viscosities, suitable thickening times, high compressive strengths after setting, good fluid loss control, etc., which allows for a sufficient time period in order for the cements to be placed into the wellbore at bottom hole circulating temperatures (BHCT) before setting. For example, the fluidity periods of these API cements (e.g., Class A, Class C, or Class H Portland cements) are required to be greater than 90 minutes at specified temperatures and pressures. The fluidity period (i.e., the thickening time) may be measured by determining the time required for the API cement to reach 70 Bearden units after the components are mixed. In some cases, gelation inhibitors such as sulfonated aromatic polymers and/or high temperature retarders such as sulfonated styrene maleic anhydride polymers are used to extend the thickening time of API cements.
It is also a common practice to blend non-cementitious industrial by-products with API cements in wellbore servicing for a variety of reasons, such as for example cost-reduction, reduced permeability, reduced energy consumption by utilizing less API Portland cement, and reduced disposal costs for disposing waste products. Examples of non-cementitious industrial by-products include without limitation Class F Flyash and silica fume. Pozzalonic reactions between the non-cementitious industrial by-products and calcium hydroxide generated by the API cement hydration generates additional binder materials which contribute to the strength of the set cement.
The demanding criteria imposed for an API designation results in an increased production cost for these cements when compared to other cement compositions lacking the API designation. In addition, the available supply of API cements is decreasing which may be attributed to their relatively expensive production costs and low usage volumes.
Other cement compositions, lacking the API designation, have not typically been used either in combination with API Portland cements or by themselves in wellbore servicing. These non-API cements typically confirm to ASTM standards, which are less demanding than the API standards. Examples of non-API cements are non-API Portland Type I cements, which are generally used in construction applications such as constructing bridges, roads, buildings, and the like. These non-API cements do not have properties suitable for servicing wellbores. For example, these cements typically exhibit a premature loss of fluidity of the cement slurry which may be tolerable for construction applications but is unsuitable for wellbore servicing applications.
Another example of non-API cements are non-cementitious industrial by-products that comprise calcium silicate materials comprising aluminates and free lime such as Class C fly ash, cement kiln dust, and blast furnace slag. These non-cementitious industrial by-products react with water causing a rapid loss of fluidity, and thus do not meet the API specifications set for wellbore servicing materials. A challenge to the use of non-API Portland cements, such as non-API Portland Type I cements and reactive industrial by-products (e.g., Class C fly ash, cement kiln dust, blast furnace slag,) is the ability to control the rheology of the cement slurry and provide process-desired rheology within the periods as specified by the API for different wellbore conditions. For example, non-API Portland cements may exhibit premature gelation, and shortened, and/or unpredictable thickening times. Thus, an ongoing need exists for materials to control the rheology of cement compositions suitable for wellbore servicing.
As mentioned in previous paragraphs, loss of slurry fluidity due to premature gelation not only provides challenges for safe placement of the slurry, but also results in slow strength development because of the lag time between the time of fluidity loss and the hydration time of the cement binder. Strength development begins with cement hydration, whereas gelled cement does not develop adequate strength to provide support for the casing and/or zonal isolation and is permanently deformable under stress. Thus, it is desirable to minimize the time lag between these phases, so that further wellbore operations can be carried out without a prolonged waiting-on-cement (WOC) duration.